1. Field of the Invention
The present invention relates generally to crude oil production and, more particularly, to the enhanced (tertiary) recovery of crude oil, especially by the injection of a solvent--such as carbon dioxide, liquified petroleum gas (LPG), or liquified natural gas (LNG)--plus water into a subterranean formation from which the crude oil is to be recovered.
2. Background Discussion
Current estimates are that over two-thirds of the crude oil already discovered in the United States, and even greater amounts in the rest of the world, are unrecoverable by known primary and secondary (such as waterflood) crude oil production processes. This "unrecoverable" oil in the Unites States alone amounts to an estimated 3.times.10.sup.11 barrels, the economical recoverability of even ten percent of which would more than double this Country's current reserves of producible crude oil.
In response to such factors as the disillusionment with nuclear power, the mid-East crises of the 1970's and the resulting dramatic increase in the cost of natural crude oil, and the rapidly dwindling reserves of readily-recoverable crude oil in the United States, considerable attention has been directed to developing effective and economical processes for the recovery of this "unrecoverable" oil so as to extend crude oil reserves. The recovery of such "unrecoverable" oil is commonly referred to as enhanced or tertiary oil recovery.
Many difficult problems are understandably associated with the enhanced recovery of crude oil, otherwise such oil would not be considered "unrecoverable." These enhanced oil recovery problems are due to such factors as the complex nature of fluid flow in underground reservoirs and the inability of producers to exercise control over the distribution and flow of fluids in the reservoirs. In this respect, underground reservoirs of crude oil typically consist of vast numbers of often small, interconnected pores and cracks in sandstone and carbonate rocks. Not only are single reservoirs typically composed of several or many different layers of rock having significantly different permeabilities, but the flow of fluid through the reservoir rocks is along a great many small, extremely tortuous and nonuniform channels and fissures which are interrupted by inclusions of shales, clays, and other materials. Thus a major problem is that when attempts are made to displace such oil by water or an expanding gas, the oil tends to be bypassed as the displacing fluid follows paths of lesser flow resistance.
Because of the large amounts of "unrecoverable" oil involved as compared with the usually much smaller amounts of oil which can be recovered by presently known primary and secondary recovery processes, a number of different enhanced oil recovery processes have been tried, with varying degrees of effectiveness. One of the most commonly used of these enhanced recovery processes is steam soaking, a process usually used for the recovery of high-viscosity oils, generally from shallow reservoirs in which the oil is at a relatively low temperature and pressure. Enhanced oil recovery rates by the use of steam soaking are, however, typically limited to no more than about 5 to 20 percent of the remaining oil in place, due primarily to the localized nature of the steam heating in the oil-producing formation and the usual inability of oil reservoirs to maintain a suitable rate of oil influx into the steam heated region around the steam injection boreholes.
The use of steam drive, as an alternative to steam heating, is generally somewhat more effective for enhanced oil recovery. However, a disadvantage is that such steam drive processes are ordinarily extremely energy intensive. For example, even for oils of normal viscosity, a third or more of the oil recovered by steam drive processes--or the energy equivalent thereof--is typically needed just to produce the driving steam used. for the enhanced recovery of higher viscosity oils by steam drive processes, the necessary steam generation can be expected to require the use of even greater percentages of the recovered oil.
Alternative fuels, such as coal and solar energy, have been suggested for generating the steam used in steam drive processes. So far, however, the proposed use of coal for producing the steam has not been practical, largely due to governmental regulations associated with the burning of coal. In turn, the proposed use of solar energy to produce the steam has not yet been proven feasible.
In another alternative enhanced oil recovery process, combustion gas generators are used to produce large volumes of hot, pressurized gas for injection into oil-bearing formations for oil heating and driving purposes. These gas generators are typically located at injection wellheads, but, in some cases, may be installed downhole so as to reduce heat and pressure losses in the gases. However, because of the difficulty in handling the hot, corrosive combustion gases and the large amounts of fuel required to generate useful quantities of combustion gases, the use of gas generators has not played an important role in enhanced oil recovery operations.
Thus, for significant amounts of "unrecoverable" oil, especially lighter oils, in the United States, the use of thermal processes, such as those mentioned above, for enhanced oil recovery has generally not been very satisfactory because of the low energy content of the recovered oil as compared to the large amount of heat energy required for heating the reservoir. This situation has naturally led to the search for more economically effective enhanced oil recovery processes; and the development of enhanced oil recovery processes involving liberation of oil through the reduction of the interfacial tension between the oil and water in the reservoir has proceeded as a less-costly alternative to energy-intensive, thermal processes. For such oil liberation purposes, drive fluids containing surfactants which reduce the interfacial tension to a low value and/or solutes which can dissolve in and swell the residual oil, so as to restore its mobility, have been used for the enhanced recovery of "unrecoverable" oil.
In laboratory oil production simulations, the capability for high-recovery yields of residual (non-recoverable) oil using aqueous solutions of micellar/polymeric surfactants with added polymers, such as polysaccharides and hydrolized polyacrylamides, has been demonstrated. Notwithstanding these promising laboratory results with the use of surfactants, when used in the field with actual oil formations, their high cost has ordinarily limited their usefulness. For one reason, the amounts of the oil-treatment materials used for enhanced oil recovery have usually been limited, because of their high cost, to no more than about 5 to 10 percent of the formation pore volume. At such low injection levels, especially considering the various material losses, absorptions, degradation, and so forth which occur, the amounts of oil recovered by the use of surfactants have usually not been particularly encouraging.
Regarding the use of solutes for enhanced oil recovery, the use of liquid petroleum gas (LPG) as a sacrificial solvent for such purpose--and even, in some cases, as an alternative to water in secondary reservoir flooding operations--was often practical when LPG was readily available and relatively inexpensive (compared to the cost of crude oil). Nevertheless, the efficiency of LPG in oil recovery operations is impaired by its mobility being much greater than that of crude oil and water. Consequently, LPG tends to finger through oil-bearing formations, with the result that usually only a small fraction of the residual oil can be recovered using LPG as an enhanced recovery solvent. Even in situations in which the low enhanced oil recovery by the use of LPG as a solvent might be otherwise acceptable, the increased cost of LPG makes its use as a recovery solvent unattractive.
Primarily because of the high cost of LPG as an enhanced oil recovery solvent, less costly oil-miscible solvents have been sought for enhanced oil recovery purposes. In this regard, carbon dioxide (CO.sub.2), when under pressure, was known to be very soluble in most crude oils and its use in enhanced recovery operations was found to lead not only to a significant volumetric increase of the crude oil but also to an advantageous decrease in oil viscosity. As a result, the use of CO.sub.2 as an injection fluid, which became popular in the 1970's , has now substantially supplanted the use of LPG in enhanced recovery operations, and accounts for at least about 85 percent of all solvents used for such operations.
Very large amounts of CO.sub.2 are normally used in enhanced oil recovery operations, the amount being dependent upon the pore volume of the particular oil-bearing formation from which the oil is to be recovered and/or the amount of oil in place in the formation, as well as upon economic considerations which are more particularly discussed below. Typically, the amount of CO.sub.2 solvent used for enhanced oil recovery is in the genera range of about 10 to about 30 percent of the formation pore volume. Because of the wide range of formation sizes and economic considerations, it is virtually impossible to define an "average" or "mean" amount of CO.sub.2 solvent used in enhanced oil recovery operations; however, the injection of more than 100 billion cubic feet of CO.sub.2 in such operations is not uncommon. Typically, the solvent injection operation continues for a number of years, with an injection time of 10-15 years not being uncommon.
Ordinarily the selected amount of CO.sub.2 used for enhanced recovery of oil is injected into the oil-bearing formation either alone in a "single slug" injection operation or with water in a series of injection cycles in which the injection of CO.sub.2 is alternated with the injection of water, the latter process being typically referred to as a water-alternating-gas (WAG) injection process. The simultaneous injection of a solvent and water, for example, by the use of separate solvent and water pumps, can be--and is herein--considered as being a WAG injection process using an infinite number of infinitesimally small injection cycles. Therefore, as used herein, the terms "WAG" injection process or "water-alternating-gas" injection process is to be construed broadly enough to include "cyclic" water and solvent injection in which the number of injection cycles may range from only a few, relatively long cycles to an infinite number of infinitesimally short cycles.
As is more particularly described below, given a particular total amount of solvent to be injected, a single slug injection process usually enables the recovery of more oil in the first few years after injection starts than does a WAG injection process. In contrast, a WAG process may, for some formations, enable the recovery of more oil 15-20 years after the start of injection, and may enable a greater overall oil recovery than would a single slug injection process which uses the same amount of solvent. However, a single slug injection process uses solvent at a faster rate than does a WAG injection process, and so early solvent costs are greater. Economic considerations are therefore important when deciding which of the two injection processes should be used for the enhanced recovery of oil from any particular oil-bearing formation.
U.S. Pat. No. 3,065,790 to Holm discloses an enhanced recovery process in which a high-pressure slug of CO.sub.2 is injected into a "vuggy" limestone formation; thereafter, a drive fluid such as an aqueous solution of CO.sub.2 is injected. After a given amount of CO.sub.2 has been injected, it is disclosed that the system is shut in and pressure in the formation is gradually reduced to a substantially lowered pressure while oil continues to be produced from the formation.
Although CO.sub.2 is usually a less-costly alternative to LPG for enhanced recovery operations, the cost of the very large amounts of CO.sub.2 needed for useful enhanced oil recovery rates is by no means small. In fact, the cost of CO.sub.2 used in enhanced recovery operations typically adds several dollars per barrel to the cost of the produced oil, thereby making tertiary oil economically unattractive as long as there exists an abundance--typically from foreign countries--of primary or secondary oil.
Considering the large amount of oil which can potentially be recovered by enhanced recovery operations and the large amount of solvents typically required for such oil recovery operations, the optimization of solvent injection processes is obviously important. It is, however, difficult, and probably impractical, to attempt to generalize regarding the selection of an "optimum" total amount of solvent to be used for enhanced oil recovery operations because of the great variation among different oil-bearing formations and the complicated, varied, and often unique economic considerations associated with each such formation. Moreover, the economic considerations involved tend to vary over time as economic circumstances and projections vary.
However, the determining of an optimum manner for injecting the solvent, once an injection amount hs been established for a particular formation, is considered by the present inventor more capable of generalization, and it is to such injection optimization that the present invention is primarily concerned.